Hydrocarbon Pore Volume Research Articles

CO2 storage associated with CO2 enhanced oil recovery: A statistical analysis of historical operations

This work analyzes a database of 31 existing CO2 enhanced oil recovery (EOR) projects that was compiled for the estimation of oil reserves to better understand the CO2 retention, incremental oil recovery, and net CO2 utilization for these oil fields. The measured data begin at the start date of the CO2 flood and extend through the year 2007. Cumulative CO2 retention (in the formation), incremental oil recovery factors, and net CO2 utilization factors were calculated for each of the sites. To express all site data on a common dimensionless scale, the data were extrapolated to 300% cumulative hydrocarbon pore volume (HCPV) by fitting nonlinear functions. Summary statistics were then calculated from 0% to 300% HCPV. Across all 31 sites, the 10th, 50th (median), and 90th percentile values for the three factors at 300% HCPV were: CO2 retention: 23.1%, 48.3%, and 61.8% retained; incremental oil recovery: 5.3%, 12.2%, and 21.5% of OOIP (original oil in place); and net CO2 utilization: 4.8, 8.7, and 10.5 Mscf/STB (stock-tank barrel). This work employs a novel approach that incorporates nonlinear functions to quantify uncertainty in the estimated values as a function of HCPV and to describe the shape of the CO2 retention or incremental oil recovery response with a handful of parameters, providing insight into the behavior of the reservoir across the entire timeline of the CO2 flood. These nonlinear curve fits are focused on statistical inference – i.e., what is the likely outcome and uncertainty ranges for CO2 retention, incremental oil recovery, and net CO2 utilization given the historical data from the 31 CO2 EOR sites? However, the approach described in this work also provides useful information for prediction – i.e., given a set of inputs from another site with similar geology, what are plausible ranges in outcomes for each of these factors? Consequently, the results of this work can be used to estimate the potential range of expected performance for similar candidate oil fields that are not currently undergoing CO2 injection, including estimates of the associated CO2 storage potential of these candidate fields. The results of this work allow estimation of CO2 storage capacity in CO2-EOR operations with various degrees of confidence. The sites in the dataset reflect water – alternating gas CO2 floods – all within the continental United States and heavily dominated by the West Texas carbonate floods. Other floods outside of this region, where the data were available, are also included in this study (i.e., the Rocky Mountain region and the State of Oklahoma).

Hydraulic Fracturing Technology Design in Natural Fracture Reservoirs

Nowadays, hydraulic fracturing has become the mainly treatment in low permeability reservoirs, but the hydraulic fracturing design technology in different reservoirs still use common methods. Natural fracture reservoirs mainly include granite reservoir, basalt reservoir and igneous rock reservoir which its hydrocarbon pore volume is fracture system. As the existing of natural fracture, hydraulic fracturing treatment always counting some problems, such as difficult sand pumping, easily screen-out and limited scale. In this paper, from the point of the reservoir characteristics, the mainly problems were analyzed and the corresponding methods were put forward .the core technique in this kind reservoir include communicating the distance nature fracture and meanwhile protecting the conductivity nature fracture. Production can reach 90% from natural fractures using numerical simulation.

Field examples of the joint petrophysical inversion of resistivity and nuclear measurements acquired in high-angle and horizontal wells

A recently introduced interpretation workflow has confirmed that inversion-based interpretation is more reliable than conventional well-log analysis in high-angle (HA) and horizontal (HZ) wells because the former accounts for well trajectory and shoulder-bed effects on well logs. Synthetic examples show that the inversion workflow could improve the estimation of hydrocarbon volumes by 15% and 10% in HA and HZ intervals, respectively. Using field examples of thinly interbedded calcite-cemented siltstone formations, we document results of the joint petrophysical inversion of logging-while-drilling multisector nuclear (neutron porosity, density, natural gamma ray, photoelectric factor) and multiarray propagation resistivity measurement for improved formation evaluation in HA/HZ wells. Under the assumption of multilayer formation petrophysical models, the inversion approach estimates formation properties by numerically reproducing the available measurements. Subsequently, inversion-derived hydrocarbon pore volume is calculated for assessment of reservoir pay. Application of the joint inversion-based interpretation in challenging field examples highlights petrophysical characteristics such as capillary trends or water saturation variations in a hydrocarbon column influenced by reservoir quality and formation electrical anisotropy which otherwise remain inconspicuous with conventional and quick-look interpretation of well-logs.

Formation-Resistivity Theory: How Archie Equations, Shaly-Reservoir Models, Conductive Rock-Matrix Model, and Dual-Triple-Porosity Models Are Related

Summary The estimation of hydrocarbon pore volume (HCPV) from resistivity logs can be quite troublesome in some complex heterogeneous reservoirs. Most water-saturation/formation-resistivity models that work well for some reservoirs give unreliable results for others. No single model works for all types of reservoir scenarios. This paper presents the theory of formation resistivity in porous media. The paper develops the theory from the parallel-resistivity model and then extends it for the series-resistivity model. When applied for clean sand, the theory derives Archie equations from the first principle. The derivations show that both porosity exponent and saturation exponent are of the same origin and should have the same name. A better name for both parameters should be the tortuosity exponent of a component with respect to its fraction in a control volume. It is also advantageous to treat as a single parameter rather than two separate parameters. In addition, this theory derives new shaly-sand models for estimating HCPV. These new shaly-sand models can be used for different types of shale distribution by adjusting the value of a single parameter in the models. The formation-resistivity theory is also used to derive formation-resistivity models for conductive rock-matrix reservoirs and dual-triple-porosity reservoirs. A new equation for calculating the composite-porosity exponent is also developed. Field data are used to validate this work. The theory, when applied for each scenario, derives formation-resistivity models for estimating the reliable HCPV of different reservoir scenarios and types. Moreover, the strength of this theory is its ability to generate models that closely resemble models that have proved to work well for the reservoir cases for which they were developed. Although this work does not test the theory for the cases of tight-sand, shale-gas, and other unconventional reservoirs because of the unavailability of such data, the author is of the opinion that the theory can easily be extended for such reservoirs if the necessary data are available.

Efficient Displacement of Heavy Oil by Use of Three Hydrocarbon Phases

Summary Mixtures of oil with solvent gas can exhibit three-hydrocarbon-phase behavior at reservoir conditions, where the solvent-rich liquid (L2) phase coexists with the gaseous (V) and oleic (L1) phases. Three-hydrocarbon-phase behavior has been studied in the literature for carbon dioxide (CO2) floods and enriched-gas floods at relatively low temperatures. Prior research on heavy-oil displacement with enriched gas presented that displacement efficiency at a given throughput can be nonmonotonic with respect to gas enrichment. Slimtube experiments for such displacements showed that oil recovery increased first, then decreased, and increased again with increasing gas enrichment. An optimum displacement with a high efficiency of more than 90% was observed when three-hydrocarbon-phase flow was present. However, detailed mechanisms for such an optimum displacement with three phases have not been explained in the literature. In this research, we investigate mass transfer on multiphase transitions between two and three phases for three-hydrocarbon-phase displacements. Simple conditions are derived for the multiphase transitions that yield high local displacement efficiency by three hydrocarbon phases. The derivation is based on the generalized mass conservation for a multiphase transition in 1D gas injection. The conditions derived are applied to explain nonmonotonic oil recovery in quaternary displacements and the West Sak oil displacements. Oil recovery at a given throughput can be nonmonotonic with respect to pressure or gas enrichment. Such a nonmonotonic trend can occur when local oil displacement by three hydrocarbon phases becomes more efficient, but slower, with decreasing pressure or decreasing gas enrichment. An optimum pressure or enrichment can occur as a consequence of the balance between the local displacement efficiency and the propagation rate of three hydrocarbon phases. The West Sak oil displacement with enriched gas studied in this research yields a high displacement efficiency of more than 90% at 1.5 hydrocarbon pore volumes (PV) injected at 53% methane (C1) dilution.

Influence of Property Modeling Practices on Estimated Hydrocarbon Pore Volume

SummaryThe emergence in geoscience of 3D geocellular modeling has raised questions about the correspondence of hydrocarbon volumetric deliverables with those derived from 2D zonal modeling. These differences of approach are compounded because the contemporary 3D methods use net-reservoir volumetric algorithms whereas the more established 2D methods have traditionally used net-pay volumetric algorithms. Both methods are initialized using 1D “along-wellbore” datasets. Key parameters for comparison are initial hydrocarbon pore volume (IHPV) for 2D and 3D modeling and equivalent hydrocarbon column (EHC) for 1D along-wellbore modeling.The focus is twofold. The first objective has been to generate a functional petrophysical model as a basis for volumetric comparisons. The reservoir notionally comprises an oil accumulation within a water-wet, lithologically-clean sandstone that is partially saturated with high-salinity brine. The sandstone comprises five rock types (RTs), each of which has a defined set of interpretive algorithms. The second objective has been to compare static volumetric estimates of EHC and/or IHPV for a range of case models. This objective was approached using three workflows. Initially, 1D along-wellbore screening studies used different case models representing various stratigraphic sequences. These allowed a preliminary assessment of results arising from the use of net-reservoir and net-pay volumetric algorithms without the influence of mapping practices. The findings were corroborated by field studies. Second, 2D zonal modeling led to values of IHPV based on both net-reservoir and net-pay algorithmic protocols. Third, 3D geocellular modeling also led to values of IHPV based on both protocols. These data allowed equitable comparisons of 2D zonal deliverables with those from 3D geocellular models because a consistent inter-well interpolation methodology was used for all 2D and 3D cases.The analysis incorporated the influence of stratigraphic sequences of the five RTs with their different petrophysical characteristics. Comparisons of 2D and 3D models showed that IHPV values delivered by established 2D zonal models with net-pay algorithmic protocols are mostly lower than those values delivered by contemporary 3D geocellular models with net-reservoir protocols by approximately 4% on average, but the differences are highly variable. These outcomes, which have implications for reserves estimation, are strongly governed by the stratigraphic distribution of the RTs. They re-emphasize that each case must be investigated separately and thoroughly.

Inversion-based petrophysical interpretation of logging-while-drilling nuclear and resistivity measurements

Interpretation of borehole measurements acquired in high-angle (HA) and horizontal (HZ) wells is challenging due to the significant influence of well trajectory and bed geometrical effects. Experience shows that accurate integrated interpretation of well logs acquired in HA/HZ wells requires explicit consideration of 3D measurement physics. The most reliable alternative for interpretation of well logs in HA/HZ wells is with inversion techniques that correct measurements for shoulder-bed, undulating well trajectory, and bed geometrical effects while taking advantage of high data resolution. We discovered an efficient layer-based inversion workflow for combined, quantitative petrophysical and compositional interpretation of logging-while-drilling sector-based nuclear (density, neutron porosity, photoelectric factor, gamma ray) and array propagation resistivity measurements acquired in HA/HZ wells. A challenging synthetic benchmark example confirmed improved formation evaluation with the layer-based inversion workflow across hydrocarbon-bearing zones in HA/HZ wells, where estimated hydrocarbon pore volume and porosity increased by 10% and 15%, respectively, with respect to conventional interpretation methods. Furthermore, application of the inversion-based method to a field example of HZ well across calcite-cemented siltstone layers confirmed its advantage over conventional interpretation techniques.

Assessment of petrophysical parameters of clastics using well logs: The Upper Miocene in El-Wastani gas field, onshore Nile Delta, Egypt

Abstract Based on logs of ten wells in the El-Wastani gas field, onshore Nile Delta, Egypt, petrophysical evaluation for the Upper-Miocene Qawasim Formation and Abu Madi Formation in the El-Wastani gas field was accomplished. The lithology of these formations was analyzed using cross plots of logging parameters, and petrophysical parameters including shale volume, porosity, water saturation and hydrocarbon pore volume were assessed. The Neutron/Density, Neutron/Gamma-ray and Litho-saturation cross plots of the wells show that the main lithology of the Lower Abu Madi unit is sandstone with shale intercalations, while the lithology of the Qawasim Formation is mainly composed of shale with sandstone intercalations. The cut-offs of shale volume, porosity and water saturation for productive hydrocarbon pay zones are 50%, 10% and 70%, respectively, which were got based on cross-plots and Gamma-ray log data. Contour maps for parameters such as net pay thickness, average porosity, shale volume and water saturation were prepared and it is found out that the Abu Madi Formation and Qawasim Formation in the study area have promising reservoir characteristics; A prospective region for gas accumulation trends northwest-southeast in the study area, especially favorable in the central part.

Effect of Carbon Dioxide Dissolving in Formation Water on the Mechanism of Oil Displacement

In order to study the effect of CO2 dissolving in formation water on the process of CO2 injection, a thermodynamic model of CO2-hydrocarbon-formation water has been used to study the dissolving law of CO2 in formation water and oil-gas-water phase behavior considering the CO2 dissolution in formation water. Based on compositional model considering the dissolution of CO2 in formation water, a dimensional model for long core CO2 displacement is presented to simulate the oil displacement efficiency, gas/oil ratio, oil or gas saturation profile, the solubility of CO2 in in-place oil or formation water with grid distance in the process of long core displacement of CO2 injection. The results show that the solubility of CO2 in formation water increases with increasing pressure and decreases with increasing temperature, and that the solubility of CO2 in formation water is usually about 5.5 wt% at the condition of reservoir pressure and temperature. In addition, oil saturation and gas phase saturation with the consideration of CO2 dissolving in formation water lag behind those without consideration of CO2 dissolution, which results in later breakthrough time for CO2 injection. Moreover, residual oil saturation with considering CO2 dissolving in formation water is higher than that without considering CO2 dissolution at the condition of the same hydrocarbon pore volume for CO2 injection, and the ultimate recovery for the former is lower than that for the latter when pouring into 0.3 hydrocarbon pore volume of CO2.

CO2 Injection in Vertical and Horizontal Cores: Measurements and Numerical Simulation

Summary In certain high-pressure and low-temperature reservoirs, the density of CO2 may be substantially higher than the oil density. Upon mixing of CO2 and oil, a gas phase with a high content of methane (C1) may also appear. When the C1 content is high, this gas phase may have a lower density than the oil. In relation to this phenomenon, we have conducted three comprehensive experiments studying CO2 injection from the top and bottom of a vertical core and injection in a horizontal core. The injection rate is 1 PV/day. This low rate allows the study of diffusion. The core diameter used in this work is 3.8 cm and the length is 27.3 cm. The tests are conducted at a pressure of 441 bar and a temperature of 60°C. At 2.6 hydrocarbon pore volume injection (PVI), the coreflood results give a recovery of 98% for bottom injection, 84% for top injection, and 92% for horizontal injection. We have also conducted an extensive set of measurements to determine swelling, viscosity, and density for the calibration of an equation of state. We simulate the experiments using a state-of-the-art higher-order finite-element three-phase compositional model. The simulations suggest that the endpoint relative permeability of the CO2-rich phase may be lower than the oil phase. The results also show that Fickian diffusion should be taken into account, but that the diffusion coefficients are reduced, because the CO2/oil mixtures are in the near-critical region for much of the injection. Even for a horizontal core there is a considerable gravity effect. One main conclusion is that there may be vast differences between CO2 injection in a 1D slim tube and in a core where there may be a 2D flow. A related conclusion is that analysis of CO2 coreflooding may provide important parameters for field-scale problems.

Improved estimation of mineral and fluid volumetric concentrations from well logs in thinly bedded and invaded formations

Calculation of mineral and fluid volumetric concentrations from well logs is one of the most important outcomes of formation evaluation. Conventional estimation methods assume linear or quasi-linear relationships between volumetric concentrations of solid/fluid constituents and well logs. Experience shows, however, that the relationship between neutron porosity logs and mineral concentrations is generally nonlinear. More importantly, linear estimation methods do not explicitly account for shoulder-bed and/or invasion effects on well logs, nor do they account for differences in the volume of investigation of the measurements involved in the estimation. The latter deficiencies of linear estimation methods can cause appreciable errors in the calculation of porosity and hydrocarbon pore volume. We investigated three nonlinear inversion methods for assessment of volumetric concentrations of mineral and fluid constituents of rocks from multiple well logs. All three of these methods accounted for the general nonlinear relationship between well logs, mineral concentrations, and fluid saturations. The first method accounted for the combined effects of invasion and shoulder beds on well logs. The second method also accounted for shoulder-bed effects but was intended for cases where mud-filtrate invasion is negligible or radially deep. Finally, the third method was designed specifically for analysis of thick beds where mud-filtrate invasion is either negligible or radially deep. Numerical synthetic examples of application indicated that nonlinear inversion of multiple well logs is a reliable method to quantify complex mineral and fluid compositions in the presence of thin beds and invasion. Comparison of results against those obtained with conventional multimineral estimation methods confirmed the advantage of nonlinear inversion of multiple well logs in quantifying thinly bedded invaded formations with variable and complex lithology, such as those often encountered in carbonate formations.

Field appraisal and accurate resource estimation from 3D quantitative interpretation of seismic and CSEM data

The key questions in field appraisal are: What is the hydrocarbon volume, and how are the hydrocarbons distributed in the field? The ability to answer these questions accurately is critical for deciding whether to produce a field and for developing a production plan. Wells drilled during the appraisal phase provide well and flow-test data, which are combined with structural knowledge from seismic surveys to map the extent of the field and generate a reservoir model. The cost for appraising an offshore field can exceed US $100 million, and it is desirable to obtain the information required with fewer wells if possible. Quantitative interpretation of surface geophysical data provides reservoir properties between well locations and can, therefore, significantly reduce appraisal costs. A quantitative analysis of seismic data using well-log information will typically determine reservoir rock porosity. Other important parameters are hydrocarbon saturation, permeability, and net-to-gross ratio. Quantitative interpretation of several reservoir properties using only the seismic data is associated with significant ambiguity. To determine several of these parameters accurately, complementary geophysical data sets with different sensitivity characteristics are needed. Controlled-source electromagnetic (CSEM) data are sensitive to the fluid type and can provide additional information to determine the hydrocarbon saturation more accurately. We have developed a new quantitative interpretation workflow integrating seismic and marine 3D CSEM data for estimating the hydrocarbon volume and obtaining 3D distributions of the hydrocarbon pore volume. A performance test of the workflow has been carried out on the Troll West Oil Province (TWOP) in the Norwegian North Sea (Figures 1 and 2). This article describes our methodology and presents encouraging results.

Quantitative interpretation of pulsed neutron capture logs: Part 1 — Fast numerical simulation

Pulsed neutron capture (PNC) logs are commonly used for formation evaluation behind casing and to assess time-lapse variations of hydrocarbon pore volume. Because conventional interpretation methods for Σ logs assume homogeneous formations, errors may arise, especially in thinly bedded formations, when appraising petrophysical properties of hydrocarbon-bearing beds. There exist no quantitative interpretation methods to account for shoulder-bed effects on Σ logs acquired in sand-shale laminated reservoirs. Because of diffusion effects between dissimilar beds, Σ logs acquired in such formations do not obey mixing laws between the Σ responses of pure-sand and pure-shale end members of the sedimentary sequence. We have developed a new numerical method to simulate PNC rapidly and accurately logs. The method makes use of late-time, thermal-neutron flux sensitivity functions (FSFs) to describe the contribution of multilayer formations toward the measured capture cross section. It includes a correction procedure based on 1D neutron diffusion theory that adapts the transport-equation-derived, base-case FSF of a homogeneous formation to simulate the response of vertically heterogeneous formations. Benchmarking exercises indicate that our simulation method yields average differences smaller than two capture units within seconds of computer central processing unit time with respect to PNC logs simulated with rigorous Monte Carlo methods for a wide range of geometrical, petrophysical, and fluid properties.

Hydrocarbon Volumetric Analysis Using Seismic and Borehole Data over Umoru Field, Niger Delta-Nigeria

Wireline signatures were used to identify hydrocarbon bearing sands and evaluate Petrophysical parameters for hydrocarbon pore volume determination. Well to seismic tie revealed that these reservoirs tied direct hydrocarbon indicators –bright and dim spots –on the seismic sections. Three hydrocarbon reservoir were delineated. Estimation of the volume of hydrocarbon in place revealed that reservoir A contained 1675091.54 ± 102 feet of gas in place, while reservoir B contained 163661.83 barrels ± 80 barrels and reservoir C contained 1739170.41 ± 102 cubic feet of gas.

RETRACTED ARTICLE: A simulation approach: Miscible carbon dioxide injection in a carbonate reservoir

The purpose of this study is to optimize the existing carbon dioxide (CO2) flood in deep dolomite formations by improving oil sweep efficiency of miscible CO2 floods and enhancing the conformance control. A full compositional simulation model using a detailed geologic characterization was built to optimize the injection pattern. The model is a quarter of an inverted nine-spot and covers 20 acres of field formation. Geologic description was used to construct the simulation grids. The simulation layers represent actual flow units and resemble the large variation of reservoir properties. History match was performed to validate the model. Several sensitivity runs were made to improve the CO2 sweep efficiency and increase the oil recovery. Finally, the optimum CO2 injection rate for dolomite formations was determined approximately. Simulation results also indicate that a water-alternating-gas (WAG) ratio of 1:1 along with an ultimate CO2 slug of 100% hydrocarbon pore volume (HCPV) will allow an incremental oil recovery of 18%. The additional recovery increases to 34% if a polymer is injected as a conformance control agent during the course of the WAG process at a ratio of 1:1. According to the results, a pattern reconfiguration change from the nine spot to staggered line drive would represent an incremental oil recovery of 26%.

EOR and CO2 disposal — Economic and capacity potential in the North Sea

Abstract To estimate the total CO 2 EOR (enhanced oil recovery) potential in the UK and Norwegian sector of the North Sea a techno-economical model for CO 2 injection into oil reservoirs and aquifers has been used in a scenario were many of the most feasible prospective water flooded fields are included. The fields are connected to a common CO 2 pipeline system to supply the optimal amount of CO 2 at any time during the CO 2 flood cycle. The technoeconomical model consists of a CO 2 transportation module and an EOR module that is integrated with an economic model that calculates investment costs and running costs both for injection into oil reservoirs and aquifers. By use of the techno-economical model a CO 2 injection scenario that includes 18 Norwegian and 30 UK oil fields in the North Sea and unspecified aquifers has been studied. The project lifetime in the scenario is 40 years where CO 2 is deposited at a constant rate of 178 million tonnes/year. The CO 2 is delivered through a main pipeline infrastructure that transports CO 2 from industrial sources in EU. In the early phases of the injection period most of the CO 2 is delivered to oil reservoirs, but throughout the period more and more CO 2 is injected into aquifers. Breakthrough CO 2 from the oil reservoirs is re-circulated. Sensitivity analyses have been made for the scenario where the oil price and the price of CO 2 for enhanced oil recovery have been varied. The potential for incremental oil production varies between 658 and 696 million Sm3, or between 8.5 and 9.0 % of the original hydrocarbon pore volume, for the various cases studied. The amount of CO 2 stored in the oil reservoirs was 2284 mill tonnes for the 40 years injection period which is 31% of the total amount stored. The purchase price for CO 2 from the sources (e.g. power industries) delivered at export terminals in Emden and Aberdeen varies between -23 and 94 USD/tonne when the oil price varies between 20 and 160 USD/bbl. For oil prices in the range 90 to 100 USD/bbl the CO 2 price is close to the cost for CO 2 capture (50 USD per tonne). An EOR module for miscible CO 2 -WAG (water alternating gas) injection has been developed. Preliminary calculations using this module indicate that the oil recovery potential for CO 2 -WAG is comparable to continuous CO 2 injection. More water and less CO 2 are produced during WAG injection, however.

Screening, Evaluation, and Ranking of Oil Reservoirs Suitable for CO2-Flood EOR and Carbon Dioxide Sequestration

Abstract Geological sequestration of CO2 in EOR operations has been recognized as one of the more viable means of reducing emissions of anthropogenic CO2 into the atmosphere in response to global climate change. This option, which lowers the cost of CO2 sequestration by recovering incremental oil, is particularly attractive in mature sedimentary basins, such as the Western Canada Sedimentary Basin where many oil pools are near depletion, and where most of the needed infrastructure is already in place. A method was developed for the rapid screening and ranking of oil reservoirs suited for CO2-flood EOR, which is particularly fit for a very large number of reservoirs as listed in eserves databases, and which does not require detailed reservoir engineering analysis. Oil reservoirs are screened on the basis of oil gravity, reservoir temperature and pressure, minimum miscibility pressure and remaining oil saturation, to determine their suitability for CO2 flooding, and an analytical method is used to calculate the incremental oil recovery at breakthrough and for any hydrocarbon pore volume (HCPV) fraction of injected CO2. In addition, the reservoir capacity for CO2 sequestration is calculated. eservoirs are ranked according to a set of criteria with corresponding assigned weights to identify and select the best-suited reservoirs for CO2 flooding and sequestration. The method was applied to 8,637 oil reservoirs listed in the 2000 Alberta reserves database. Of these, 4,470 passed the screening criteria and were ranked based on technical and performance characteristics. Preliminary calculations predict that 150 × 106, 422 × 106, or 558 × 106 m3, of additional oil could be produced from Alberta's reservoirs at breakthrough, and at 50% and 100% HCPVof injected CO2, respectively; meanwhile sequestering 127, 591 and 1,118 Mt CO2, respectively. Thus, geological sequestration of CO2 in Alberta oil reservoirs suitable for CO2 flooding could provide a means for significantly reducing anthropogenic CO2 emissions from major point sources while, at the same time, realizing an economic benefit. Introduction As a result of anthropogenic CO2 emissions, atmospheric concentrations of CO2 have risen significantly from pre-industrial levels, primarily as a consequence of fossil-fuel combustion for energy production. Circumstantial evidence suggests that the increase in greenhouse-gas concentrations in the atmosphere leads to climate warming and weather changes(1). In response to the need to avoid irreversible climate changes and the associated risks resulting from greenhouse effects, most of the developed world, including Canada, has committed to reduce by 2012 the release into the atmosphere of anthropogenic CO2 to levels below those of 1990. However, although the intensity of CO2 emissions has markedly decreased, Canada's emissions have increased steadily since 1990 as a result of economic development. Given the inherent advantages, such as large resources, availability, ease of transport and storage, and competitive cost, fossil fuels, which currently provide about 75% of the world's energy, will likely remain as a major component of the world's energy supply for at least this century(1, 2). In light of this, producing regions, such as Western Canada, need to find ways to both increase oil production and reduce CO2 emissions.

Integrated reservoir characterization and uncertainty analysis, Heidrun Field, Norway

The Lower Jurassic Åre and Tilje Formations of the Heidrun Field contain some 350 × 10 6 Sm 3 (2160 × 10 6 BBL) of oil in place. The reservoirs are highly heterogeneous and represent deposition in a wide range of fluvial, tidal and marginal marine environments. This, together with a high level of faulting and a relatively viscous oil type, has led to low recovery estimates. To help improve recovery, an integrated reservoir description project including a thorough sedimentological analysis, stochastic modelling of genetic and diagenetic facies, and an associated uncertainty analysis also using stochastic modelling was initiated. Facies architectures were modelled in 17 individual reservoir zones, each zone consisting of up to 10 × 10 6 grid blocks. The Åre Formation is characterized by alluvial plain and low energy deltaic systems, including incised valley fills, fluvial channels, crevasse splays, upward coarsening bayfills and large splay lobe deposits. The overlying Tilje Formation is characterized by mixed tidal and marginal marine depositional systems with tidal channels, tidal sand and mud flats, tidal shoals and shoreface and offshore sands. Several facies were modelled within each zone and the desired facies architecture was often achieved by merging several individual stochastic realizations. Input to the facies modelling was based on well data as well as information from outcrop analogues and modern depositional systems. Petrophysical attributes were distributed stochastically within each facies body type, using frequency distributions from the wells and interpreted variogram functions. The realizations were finally fitted to the structural maps and upscaled for flow simulation. This enabled the building of a ‘best guess’, or most likely, full-field geological and dynamic simulation model. A subsequent uncertainty study integrated and evaluated the full spectrum of geological and petrophysical uncertainties related to the dynamic behaviour of the reservoir including facies geometries and facies volume fractions. Best, worst and intermediate case facies realizations with respect to fluid flow were first generated using stochastic modelling. These were combined with other major reservoir uncertainties (gross rock volume, petrophysical values) and 150 complete geological models were established. The hydrocarbon pore volume in each of these models was calculated, and the models were taken through a simplified flow simulation. The results from this process allowed a ranking of the models and a selection of representative models for further dynamic flow simulations. The uncertainty study shows that the uncertainty related to the gross rock volume is the most significant on a field-wide scale. Uncertainties in the facies input parameters (geometry, facies volume fraction) have relatively little impact at a field wide scale. However, their impact upon individual zones or segments (local scale) can be large.

Application of a General Material Balance for High-Pressure Gas Reservoirs

Summary This paper presents the derivation of a general gas material balance that has particular application to high-pressure gas reservoirs, [both normal pressured and overpressured (geopressured)]. Its main application is to calculate original gas in place and assist in calculating remaining recoverable reserves from pressure/production data. The form of the material-balance equation is (p/z)[1−c¯e(p)(pi−p)]=(p/z)i(1−Gp/G),, which includes a pressure-dependent cumulative effective compressibility term c¯e(p) that is defined in terms of the following reservoir parameters: pore compressibility, water compressibility, gas solubility, and total water associated with the gas reservoir volume. "Associated" water includes connate water, water within interbedded shales and nonpay reservoir rock, and any limited aquifer volume. c¯e physically represents the cumulative change in hydrocarbon pore volume (PV) caused by compressibility effects and encroaching water. High pressure gas reservoirs typically have concave downward p/z vs. Gp plots which may result in serious overestimation of original gas in place and remaining recoverable reserves. The proposed form of the gas material balance equation provides a method to linearize the p/z vs. Gp plot, and thereby predict the true original gas in place. A method is suggested to determine initial gas in place by analyzing the behavior of cumulative effective compressibility backcalculated from pressure/production data. The c¯e(p) function determined by this procedure, or estimated from logs and geological maps when sufficient production data is not available, is then used to forecast pressure/cumulative behavior. Two field examples are provided showing the application of the material balance equation to high pressure gas reservoirs.

Quantification of Reservoir Connectivity for Reservoir Description Applications

Summary This study investigates means for efficiently estimating reservoir performance characteristics of heterogeneous reservoir descriptions with reservoir connectivity parameters. We use simulated primary and waterflood performance for two-dimensional (2D) vertical, two- and three-phase, black oil reservoir systems to identify and quantify spatial characteristics that control well performance. The reservoir connectivity parameters were found to correlate strongly with secondary recovery efficiency and drainable hydrocarbon pore volume. We developed methods for estimating primary recovery and water breakthrough time for a waterflood. We can achieve this estimation with three to five orders of magnitude less computational time than required for comparable flow simulations.